As more distributed renewable generation is incorporated into the grid, well regulated conventional generation will be displaced by stochastic energy sources that can have adverse effects on the power system if not managed properly. It is well known that high penetrations of PV may have negative local impacts, including voltage rise, reverse power flow, power fluctuations, power factor changes, and unintentional islanding. In addition, there have been concerns that sufficiently high penetrations of PV may have negative wide-area impacts. Recent studies that consider the impact of PV on low frequency inter-area modes have reported that greater PV penetration may “detrimentally affect the inter-area mode” through reduction in damping or introduce the potential for new oscillatory modes. Anticipating the high penetration of PV distributed energy resources (DER) has thus led to significant changes in utility interconnection requirements that include voltage and frequency regulation requirements and voltage and frequency ride through requirements. These new requirements will help to avoid the aforementioned problems, but unfortunately they may decrease the efficacy of anti-islanding schemes. In particular, the IEEE 1547 standard requires that distributed generators detect an island and cease to energize within 2 seconds for all cases, regardless of the number or type of distributed generation or the loading conditions. Compliance is established through application of the IEEE 1547.1 anti-islanding test.
Furthermore, the anticipated high penetration of distributed photovoltaic (PV) energy sources is expected to lead to significant changes in utility interconnection requirements for PV systems. These changes will include provisions for voltage and frequency regulation capability, as well as better voltage and frequency ride through requirements. For DER to provide grid support, it must participate in frequency and voltage regulation. Frequency and voltage ride through allows inverters to remain connected to ensure robust recovery in the event of voltage and frequency disturbance. Implementing these advanced capabilities is essential to mitigating the negative impacts of high penetration PV, but their integration into a typical distribution system presents significant technical challenges, one of which is the increased risk of unintentional islanding.
Historically, subharmonic power line carrier signals have been injected into the distribution feeder by installing a signal generator and an injection transformer that acted essentially as a large nonlinear load. Consider the generic distribution feeder 20 depicted in FIG. 1. Feeder 20 generally includes feeder series impedances 22, load blocks 24, 26, 28, 30, 32, 34, and distributed generators 36, 38, which are in this case, photovoltaic (PV) systems. Voltage source Utility V at the left, along with its source impedance Source Z, represent the grid from the standpoint of feeder 20.
Feeder 20 is fully connected to the grid when feeder breaker 40, recloser 42, and sectionalizer 44 are all closed. When the grid connection of feeder 20, or some portion of it, is lost, feeder 20 becomes an island, as may happen for example if feeder breaker 40 opens. In this conventional system, a power line carrier (PLC) signal generator SG is paired with two PLC signal receivers SR, one at each PV plant 36, 38. Typically, the subharmonic PLC signal is generated by shorting the SG transformer secondary to ground periodically, usually very close to the zero crossing of the voltage waveform in order to minimize currents in the harmonic components. The subharmonic signal is limited to be an integral subharmonic of the line frequency. This technique has been used for quite some time, but it requires a signal generator that can tolerate high currents, and an injection transformer 46 that carefully balances current limiting requirements with access impedance needs. Thus, the costs of this type of implementation are often sufficiently high that they serve as a barrier to the use of this technique for preventing islanding in DERs. In addition, the relatively large physical footprint of the SG and transformer 46 often cause difficulties in siting the SG in a utility substation.
A need remains, therefore, for systems and methods that enable reliable detection of island formation, in the presence of any combination of DERs, and with DERs incorporating grid support functions.